A variety of processes have been used for displacing petroleum that is not recovered by natural depletion or by water flooding from a subterranean reservoir. The enhanced recovery fluids used for displacing the petroleum may be classified as aqueous and non-aqueous. In general, these processes involve injecting an aqueous solution of a chemical or a non-aqueous fluid into the reservoir through injection wells, driving the fluid from one well to the other, and recovering oil ahead of the fluid through production wells. The processes are often applied after the production wells are producing only water. There can be a significant time lapse from the time the enhanced recovery fluid is injected into injection wells and the time the additional oil to be recovered by the process is fully recovered from production wells. This delay in time causes extra operating expense for the recovery process and extra investment cost, since the injection fluid must be purchased at the beginning of the enhanced recovery process. It is generally desirable to complete the recovery process in as short time as feasible.
The rate at which fluids can be injected into wells normally limits the rate at which recovery processes can be operated. The rate of fluid injection is determined by the reservoir permeability around the well to the fluid being injected, the viscosity of the fluid, the well spacing and the pressure of injection. Injection pressure is often limited by fracturing pressure of the formation where the fluid is being injected. If injection pressure is so high as to create hydraulic fractures, the flow pattern during the displacement of the petroleum is drastically affected and sweep efficiency of the enhanced recovery fluid may be greatly reduced. Also, the expensive recovery fluid may be lost to surrounding formations through a fracture.
Since the flow velocity of fluid near an injection well is much higher than at a remote location from the well, the permeability to the enhanced recovery fluid very near the well has a much greater effect in determining injection rate of the fluid. The permeability to flow of a fluid is dependent on the saturation or amount of other fluids present in the pore spaces near the injection well. The term "relative permeability" is used to describe the ratio of the permeability to a particular fluid in the presence of other fluids within the pore space to the absolute permeability of a rock. The relative permeability of each fluid increases as the saturation of that fluid increases within the pore space. Therefore, if the saturation of a fluid being used to flood a reservoir can be increased in the near-wellbore region, the permeability to that fluid can be increased. If the permeability is increased in the near-well region, where velocities are highest, the enhanced recovery fluid can then be injected at a higher rate.
Relative permeability data are obtained for reservoir rock in laboratory experiments using core samples cut from the reservoir of interest. The data for a particular fluid depend on the geometry of the pore spaces of a particular type of rock, the wetting conditions of the surface of the rock, and the properties of other fluids present. The effect of a change in saturation of a particular fluid on the permeability of another fluid can be measured directly by measuring changes in the permeability to the second fluid. The effect in different rock samples will vary considerably, depending on the properties of that particular rock.
In displacing one fluid by another in rock, there are immiscible and miscible displacements or floods. The miscible displacements replace one fluid with another with which it is miscible, the displacement being subject to mixing and dispersion processes in the rock matrix. The fluid with which the displacement fluid is not miscible may not be displaced below a certain saturation in the pore spaces, but will be displaced to lower saturations if co-solubility exists between the immiscible fluids. Since the volume near an injection well that must be affected to alter saturations of the fluids and relative permeability to a fluid is such a small fraction of the total volume of a reservoir to be flooded for enhanced oil recovery, processes can be considered for altering the near-well permeability to a fluid that are not suitable, because of mixing and dispersion, lack of miscibility, cost of the fluid or other reasons, for flooding a reservoir for enhanced oil recovery.
The most widely used flooding process for increased oil recovery has been carbon dioxide flooding. Carbon dioxide has a critical pressure and temperature lower than the pressure and temperature of most oil reservoirs, so it is injected as a super-critical fluid. Under most reservoir conditions, it is not miscible with the reservoir water, and it may or may not be miscible with the reservoir oil. However, even if the carbon dioxide is not completely miscible with the reservoir oil, it can be highly soluble in the oil and can cause the oil phase to swell in volume and decrease in viscosity. It may cause heavier hydrocarbons in some crude oils to separate and form a material that can block pore spaces of the rock.
Carbon dioxide injection is often followed by water injection. Commonly, alternate slugs or banks of water and carbon dioxide are injected, to prevent the low-viscosity carbon dioxide from rapidly fingering through a reservoir and to increase the conformance or sweep efficiency of the carbon dioxide flood. The relative permeability to carbon dioxide is determined by the saturation of both the water and oil in the pore spaces of the rock. The very reason the water banks are injected, however, to decrease mobility of carbon dioxide in the rock, is counter-productive when injectivity of carbon dioxide is considered. The injection rate of carbon dioxide becomes limited by the high saturation of water around injection wells. The same effects occur when the enhanced recovery fluid is another non-aqueous fluid, such as nitrogen gas or hydrocarbon gases, such as methane and mixtures of methane and heavier hydrocarbons, instead of carbon dioxide.
There is a need for a method to increase the permeability of carbon dioxide or other non-aqueous enhanced recovery fluid in the rock near injection wells, so as to increase the injection rate of this fluid into a reservoir at the same injection pressure and, thereby, allow more rapid recovery of the petroleum displaced by the enhanced recovery fluid.